Olefins, such as ethylene, propylene, butylene, and butadiene are vital to the petrochemical industry because they are the industry's basic building blocks. Consequently, there is a great demand for such olefins, and any technology that can increase olefin yield will have substantial economic value. Olefins are typically produced in steam crackers where suitable hydrocarbons are thermally cracked to produce lighter products, particularly ethylene. Typical stream cracker feedstocks range from gaseous paraffins to naphtha and gas oils. In steam cracking, the hydrocarbons are pyrolyzed in the presence of steam in tubular metal coils within furnaces. Steam acts as a diluent and the hydrocarbon cracks to produce olefins, diolefins, and other by-products. Thermal conversion in steam crackers is limited, among other things, by coking in the tubular metal coils. Typical steam cracking processes are described in U.S. Pat. Nos. 3,365,387 and 4,061,562 and in an article entitled "Ethylene" in Chemical Week, Nov. 13, 1965, pp. 69-81, all of which are incorporated herein by reference.
Olefins can also be produced in fluid catalytic cracking process units. In fact, many petroleum refiners are adjusting their fluid catalytic crackers to produce more olefins, at the expense of gasoline, to meet market demand. Fluid catalytic cracking employs a catalyst in the form of very fine particles which behave like a fluid when aerated with a vapor. The fluidized catalyst is continuously circulated between a reactor and a regenerator and serves as a vehicle to transfer heat from the regenerator to the feed and to the reactor. Most fluid catalytic crackers today use relatively active zeolitic catalysts which are so active that a minimum catalyst bed is maintained and most of the reactions take place in a riser, or transfer line, from the regenerator to the reactor. Further, catalysts with improved selectivity to high value light olefins are continuing to be commercialized.
It has been found, by the inventors hereof, that increasing the hydrogen content of heavy feeds is directly related with reduced tar yields in a steam cracker and reduced coke-make in a fluid catalytic reactor, resulting in a higher production of olefins, especially ethylene in both. Non-limiting examples of such feeds include vacuum gas oil (VGO), atmospheric gas oil (AGO), heavy atmospheric gas oil (HAGO), steam cracked gas oil (SCGO), deasphalted oil (DAO), light cat cycle oil (LCCO), vacuum resid, and atmospheric resid. Such streams can undergo catalytic hydroprocessing to remove heteroatoms such as sulfur, nitrogen, and oxygen, and to hydrogenate aromatics before being introduced into a steam cracker or fluid catalytic cracker.
Catalytic hydroprocessing is an important refinery process owing to ever stricter governmental regulations concerning environmentally harmful sulfur and nitrogen constituents in petroleum streams. Another desirable effect of hydroprocessing is the saturation and mild hydrocracking of aromatics in the feed, particularly polynuclear aromatics. The removal of heteroatoms from petroleum feedstocks is often referred to as hydrotreating and is highly desirable because there is less need for extensive separation facilities downstream of the cracker process unit when the heteroatom level is low. Further, heteroatoms such as sulfur and nitrogen, are known catalyst poisons. Typically, catalytic hydroprocessing of liquid-phase petroleum feedstocks is carried out in cocurrent reactors in which both the preheated liquid feedstock and a hydrogen-containing treat gas are introduced to the reactor at a point, or points, above one or more fixed beds of hydroprocessing catalyst. The liquid feedstock, any vaporized hydrocarbons, and hydrogen-containing treat gas all flow in a downward direction through the catalyst bed(s). The resulting combined vapor phase and liquid phase effluents are normally separated in a series of one or more separator vessels, or drums, downstream of the reactor. The recovered liquid stream will typically still contain some light hydrocarbons, or dissolved product gases, some of Which, such as H.sub.2 S and NH.sub.3, can be corrosive. The dissolved gases are normally removed from the recovered liquid stream by gas or steam stripping in yet another downstream vessel or vessels, or in a fractionator.
Conventional co-current catalytic hydroprocessing has met with a great deal of commercial success, however, it has limitations. For example, because of hydrogen consumption and treat gas dilution by light reaction products, hydrogen partial pressure decreases between the reactor inlet and outlet. At the same time, any hydrodesulfurization or hydrodenitrogenation reactions that take place results in increased concentrations of H.sub.2 S, and/or NH.sub.3. Both H.sub.2 S and NH.sub.3 strongly inhibit the catalytic activity and performance of most hydroprocessing catalysts through competitive adsorption onto the catalyst. Thus, the downstream portion of catalyst in a trickle bed reactor are often limited in reactivity because of the simultaneous occurrence of multiple negative effects, such as low H.sub.2 partial pressure and the presence of the high concentrations of H.sub.2 S and NH.sub.3. Further, liquid phase concentrations of the targeted hydrocarbon reactants are also the lowest at the downstream part of the catalyst bed. Also, because kinetic and thermodynamic limitations can be severe, particularly at deep levels of sulfur removal, higher reaction temperatures, higher treat gas rates, higher reactor pressures, and often higher catalyst volumes are required. Multistage reactor systems with stripping of H.sub.2 S and NH.sub.3 between reactors and additional injection of fresh hydrogen-containing treat gas are often employed, but they have the disadvantage of being equipment intensive processes.
Another type of hydroprocessing is countercurrent hydroprocessing which has the potential of overcoming many of these limitations, but is presently of very limited commercial use today. U.S. Pat. No. 3,147,210 discloses a two stage process for the hydrofining-hydrogenation of high-boiling aromatic hydrocarbons. The feedstock is first subjected to catalytic hydrofining, preferably in co-current flow with hydrogen, then subjected to hydrogenation over a sulfur-sensitive noble metal hydrogenation catalyst countercurrent to the flow of a hydrogen-containing treat gas. U.S. Pat. Nos. 3,767,562 and 3,775,291 disclose a countercurrent process for producing jet fuels, whereas the jet fuel is first hydrodesulfurized in a co-current mode prior to two stage countercurrent hydrogenation. U.S. Pat. No. 5,183,556 also discloses a two stage co-current/countercurrent process for hydrofining and hydrogenating aromatics in a diesel fuel stream.
U.S. Pat. No. 4,619,757 teaches a two stage process for the production of olefins from heavy hydrocarbon feedstocks wherein the feedstock is hydrotreated in a first stage followed by a subsequent thermal cracking. The first stage employs a zeolitic hydrotreating catalyst, such as a faujasite structure combined with a metal selected from groups VIB, VIIB, and VIII or the Periodic Table of the Elements. The second stage employs a conventional non-zeolitic catalyst, such as those which contain a catalytic amount of molybdenum oxide and either nickel oxide and/or cobalt oxide on a suitable catalyst support, such as alumina.
Although it is known that countercurrent hydroprocessing is more efficient than co-current hydroprocessing, and that hydrotreating can improve the value of feedstocks for thermal and catalytic cracking, it was not known that for the same level of hydrogen in the upgraded feed, a higher yield of olefins will result from a stream which is the product of a countercurrent hydroprocessing process as opposed to a co-current hydroprocessing process. Therefore, there still remains a need in the art for process improvements that will result in increased yields of olefins, particularly ethylene.